Hydraulic fracturing design and 3D modeling: a case study from Cambay Shale and Eagleford Shale

  • Vaishali SharmaEmail author
  • Anirbid Sircar
  • Anand Gupta
Original Paper


Economically producing oil and gas from low permeable unconventional shale gas reservoirs has been made possible by the implementation of hydraulic fracturing with horizontal drilling and microseismicity. This new technique can drastically transformed the energy future of India. Hydraulic fracturing improves well productivity and enhances the production from ultra-low permeable formations. An optimum fracture design can help in understanding the pressure distribution inside the fracture and the fracture geometry (length, width and height). The present study is an attempt to design a hydraulic fracture model for Cambay Shale in a 3D simulator to assess the application of this advance technology in clay-rich shale of India. It also follows in parallel, a fracture design and modeling of Eagleford Shale, USA. It was observed that Cambay Shale has less frac height and frac half-length as compared to Eagleford Shale due to clay richness of Cambay. A clay conditioner may be used before implementing the hydraulic fracturing job in shale sections of Cambay. This can help in attaining more fracture growth and propagation.


Hydraulic fracturing Fracture geometry Cambay Shale Fracture propagation 

List of symbols


Injection flow rate

\(\tau \)

Time of fracture leakoff area creation


Fracture volume


Fluid loss (no spurt loss)


Volume loss by spurt




Total leakoff coefficient


Leakoff area (one face of the fracture)


Spurt loss coefficient

\(\alpha _a\)

Leakoff area parameter

\(\alpha _c\)

Leakoff parameter during pumping

\(\alpha _{c2}\)

Reservoir compressibilty and viscosity coefficient

\(\upalpha \tau \)

Leak off parameter at the time of fracture


Pumping time

\(\vec {\nabla }\) P

Change in pressure

\(\Theta \)

Dimensionless time

\(\Phi \)



Fracture width


Darcy friction factor


Reynolds Number

\(\uprho \)


\(\upvarepsilon \)

Relative wall roughness

\(\Gamma _{\mathrm{w}}\)

Generalized influence function

\({{H}}_{\upxi }\)

Characteristic half height

G (\(\Theta \))

Fluid loss function

\(\Delta P\)

Is the net fracture pressure \({P} - \sigma \)


Critical stress intensity factor

\(\Pi \)

Pie (3.14)


Lateral coordinate along fracture length


Coordinate perpendicular to frac face


Vertical coordinate


Shear modulus


Poisson’s ratio

1 Introduction

Hydraulic fracturing stimulation is the most widely accepted key technology for the development of shale gas reservoirs. Since the shale gas reservoirs have very tight nature with low permeability, to make them flow at an economically viable rate and achieve highest ultimate recovery, simulation by hydraulic fracturing is necessary (Sharma et al. 2010). Shale fracturing is unique in several aspects when compared to fracturing conventional reservoirs as this oil- and gas-rich formation is having very low to extremely low permeability (Saldungaray and Palisch 2012). Hydraulic fracturing has been proved as a well-established stimulation technique to enhance the oil and gas production from these low to extremely low untapped permeable reservoirs (Al-Muntasheri 2014; Corrin et al. 2015; Janszen et al. 2015). This technique increases the hydrocarbon productivity by establishing a positive communication between the formation and the wellbore (Saldungaray and Palisch 2012; Sirat et al. 2014). Recent technologies and advance completion methods like—Plug and Perf coupled with multi-stage hydraulic fracturing (Janszen et al. 2015), microseismicity application (Sorrells and Mulcahy 1986), real-time on-site monitoring, control and fracture mapping (Veatch and Moschovidis 1986), frac and pack (Meese et al. 1994), CT deployed hydrajet perforating (McDaniel et al. 2006) and zipper frac (Rafiee et al. 2012a, b) have been successfully implemented to acquire economic and sustainable production from oil/gas shale wells (Ebinger 1998; Casero et al. 2008; Centurion 2011; Rahm 2011; Bello and Wattenbarger 2010; Yu and Sepehrnoori 2013; Vermylen and Zoback 2011; Rafiee et al. 2012a, b).

In the hydraulic fracturing stimulation technique, viscous fluids are pumped at high pressure to initiate the fracture followed by the subsequent transport of sand/proppant (Al-Muntasheri 2014; Nikurova et al. 2006). These highly conductive proppants maintain a conductive path for the hydrocarbons to flow from reservoir to the wellbore. Optimum fracture designing and real-time monitoring are the two key important parameters for a successful hydraulic fracturing job. The design process must attend to multiple parameters such as—Wellbore placement and lateral length, completion techniques, no. of fracs and fracture geometry and conductivity (Saldungaray and Palisch 2012). The typical fracturing design considerations include (1) well productivity for various fracture lengths (2) parametric studies on fracture geometry (3) fracturing fluid selection (4) in situ stress distribution (5) geomechanical properties (6) presence of natural fractures and (7) fracture treatment schedule (Rickman et al. 2008; Lee and Advani 1992; Rafiee et al. 2012a, b; Rahman et al. 2001; Veatch 1983). A combination of all these factors can augment in determining the entire economic viability of the proposed fracturing treatment (Hareland et al. 1993; Rahman et al. 2001; Veatch 1983). An optimized design for fracture placement, along the wellbore, should create large fracture surface area and sufficient fracture width to allow proppant settling, forming a conductive path from formation to the wellbore (Rafiee et al. 2012a, b; Mullen et al. 2010).

Geomechanical properties of rock plays an essential role in understanding the shale completion practice, fracture characteristics (failure behaviour) and geometry (Leem and Reyna 2014; Rickman et al. 2008). There are three principal components of local in situ stresses, typically, compressive, anisotropic and nonhomogeneous stresses which are influenced by weight of the overburden, pore pressure, temperature, rock properties, tectonics, diagenesis and viscoelastic elongation (Gidley et al. 1989). These local stresses affect the fracture initiation, growth, breakdown and extension. A fracture is initiated and extended when sufficient differential hydraulic pressure is applied to overcome these compressive in situ stresses (Gidley et al. 1989). Normally, a fracture is created perpendicular to the minimum in situ stresses. Numerous models have been presented to predict the fracture propagation and its geometry (i.e., height, width and length) (Mendelsohn 1984; Cleary 1980). These models can also simulate the production from the created fracture geometry. Conventional models such as PKN, PN, circular fracture model, 3D models and pseudo-3D fracture models have been widely used and applied for fracture modeling and simulation (Geertsma and Haafkens 1979; Daneshy 1973; Nordgren 1972; Advani et al. 1990; Lee et al. 1990; Adachi et al. 2007). Both 2D and 3D models include a rectangular and a radial (circular) propagation mode (Gidley et al. 1989) and capable of predicting fracture propagation, fluid leak off and heat transfer, fracture closure, clean up and post fracture performance (Settari 1980; Ji et al. 2009).

A numerical method of solution to solve the reservoir flow equations, the fracture flow equations and fracture geometry equation is presented by Nghiem et al. (1984). The problem of computing the geometry of a hydraulic fracture is closely related to the (1) pressure distribution inside the fracture due to the injection fluid flow and (2) fracture mechanics. Thus, fracture modeling solution essentially consists of the mathematical matching of treatment schedule and fracture mechanics of the process (Daneshy 1973). The procedure used for the design and study of hydraulic fracture in this paper consists of following sequential steps—(1) pumping the fracturing fluid resulting in opening of fracture, (2) increasing the pressure and proppant placement in the fracture. (3) Leaking off the fluid into the formation. During all these steps, the fracture growth (i.e., height, width and length of the fracture) will be monitored.

In the present study, a hydraulic fracture design and model of Cambay vs Eagle Ford Shale is presented with the use of rock mechanics, well design and petrophysical data. The geomechanical and well data for Eagle Shale is taken from the open source literature (Araujo et al. 2012). For the Cambay Shale, the data was generated experimentally with the help of research and development laboratories and industries.

It was observed that less stress zone is the geomechanically favourable area for hydraulic fracture initiation, however, the rock quality in terms of porosity, permeability, hydrocarbon saturation should be given similar weightage or higher weightage to predict the production. Cambay Shale shows less frac height and frac half-length as compared to Eagleford. It is probably due to high clay content of cambay shale which is around 50–60%. Clay conditioning in Cambay shale can give better fracture geometry. Application of hydraulic fracturing in Cambay Shale is at preliminary stage. This study can be useful in predicting the shale fracability and producibility in India.

2 Shale reservoir description

2.1 Cambay Shale (Cambay Basin, India)

Cambay basin is situated in the Gujarat state of India with an aerial coverage of 53,500 \(\mathrm {km}^{2}\). It has been prognosticated as the main shale gas reservoirs with resource potential of around \(89.22 \, \mathrm {BCF/km}^{2}\), high organic matter content (3.0%) and good thermal maturity. Based on the various pilot investigations on Cambay Shale sections, it has been observed that this Shale is a potential hydrocarbon source rock, thermally matured and falls within oil window with total organic carbon (TOC) values in between 4 and 5% (average, Upper Cambay Block) and Hydrogen Index values from 150 to 100 mg HC/gm TOC (Mathuria et al. 2011). The thermal maturity in South Cambay (i.e., 0.5–1.8%) is higher than the north Cambay (i.e. 0.6–0.8%) (Padhy 2017). If a shale is thermally matured, it means it has the potential to transform organic matter into thermogenic gas under the effect of temperature, critical time, burial depth and pressure.

A pilot experimental investigation was performed on the shale samples of North Cambay basin in the University of Oklahoma, USA to assess the mineralogy and petrophysical properties of this shale. Through the Fourier transform infrared spectroscopy (FTIR) measurement, it was observed that it is rich in clay content with illite as the dominant clay mineral. However, permeability investigations shows very low permeability of the samples.
Fig. 1

a (Left) SEM image at horizontal flow width \(319 \, \upmu \hbox {m}\) and b (Right) shows the FTIR results which indicates that the sample is rich in clay content (i.e., 61%) with porosity 11%. Quartz is the second dominant mineral present in the sample. c SEM images of core drilled through Eagle Ford Shale (Araujo et al. 2012). d Geomechanical log of drilled sections (Araujo et al. 2012)

These experimental investigations were augmented with imaging testing i.e., scanning electron microscopy which confirms that the shale is clayey in nature with good percentage of organic and natural pores. During hydraulic fracturing treatment, enormous amount of water is used, so, there is a possibility of clay swelling. A clay inhibitor/conditioner may be used to protect the formation. Figure 1a, b depicts the SEM image and FTIR results of one of the sample of Cambay Shale.

2.2 Eagle Ford Shale formation

The Eagleford Shale is a world-class Type-II marine source rock, which is located below the Austin Chalk and above Buda lime, with an estimated recoverable reserves of approximately 150 TCF (Araujo et al. 2012). Figure 1c illustrates the examples of samples evaluated using SEM.

The mineralogy test shows that the percentage of clay-rich minerals is very low (for example illite ranging from 4 to 5%). However, the quartz content is high i.e., 19–73% (Araujo et al. 2012). It is a thermally matured shale with TOC values in between 1 and 5% and porosity 6.5%. The geomechanical properties are evaluated from log Fig. 1d.

2.3 Comparison and contrast of Cambay and Eagle Ford Shale

Cambay Shale and Eagleford Shale is compared to get the contrasting attribute. Both are from different geological age. Cambay Shale is tertiary in nature, whereas Eagleford is from late cretaceous age. Despite having contrasting features, both shales are thermally mature with average TOC content in the range of 1–8%. The shales are chosen because they are oil rich and sandwiched between a reservoir rock (carbonate) and a tight formation (frac barrier). Eagleford Shale was examined as an example case study to map and correlate the fracture modeling and design in Cambay Shale. The important comparable and contrasting attributes of these two shales from fracture design point of view are shown in Table 1.
Table 1

Compare and Contrast of Cambay and Eagleford Shale (EIA/ARI 2013)


Cambay Shale

Eagleford Shale

Geological age


Late Cretaceous



Calcareous Shale

Lower formation


Buda (tight formation)

TOC (%)

2.6% (average)




0.7–1.8 %

Clay Content






Kerogen type



HC window

Oil window

Oil condensate, dry gas

Reservoir pressure

Moderately overpressurized


3 Simulator description and well design

Simulator description: MShale is a simulator with discrete fracture network functionality designed for simulating three-dimensional hydraulically induced fracturing propagation in ultra-low permeable unconventional reservoirs e.g., shales. It is applicable when half-length to half height aspect ratio is greater than about 1/3. It offers options for designing 2D Models also. The version of this software is “MShale version 5.80.2303 (64-bit)”

This hydraulic fracturing simulator is created by the incorporation of two fundamental basic science components i.e., (1) fracture mechanics and (2) fluid mechanics. These two components affects the overall fracture growth, propagation and producing capacity of rock. The governing equations of mass conservation, continuity, momentum conservation, width opening pressure, fracture propagation criteria and constitutive relationships are discussed below which can be used for fracture propagation modeling and optimization. (Meyer 2012)

Mass conservation equation (Meyer 2012)

The governing mass conservation equation for an incompressible slurry to be pumped in the created fracture can be expressed as Eqs. 1, 2, 3 and 4
$$\begin{aligned} \int \limits _0^t q (\tau ) d \tau - {\hbox {V}}_{\mathrm{f}}(\hbox {t}) - {\hbox {V}}_{\mathrm{i}}(\hbox {t})- {\hbox {V}}_{\mathrm{sp}}(\hbox {t}) = 0 \end{aligned}$$
$$\begin{aligned} \mathrm {V}_{\mathrm{l}}(\mathrm {t})= & {} 2 \int \limits _0^t \int \limits _0^A \frac{C ({A,t})}{[{t-\tau (A)}]^{\alpha \tau }} \mathrm{{d}}{} \textit{A}\mathrm{{d}}{} \textit{t} \end{aligned}$$
$$\begin{aligned} \hbox {Vsp(t)}= & {} 2 \, \hbox {SpA(t)} \end{aligned}$$
$$\begin{aligned} \tau (A)= & {} t \left[ {\frac{A}{A (t)}}\right] ^{\alpha \mathrm{a}} \end{aligned}$$
where q is injection flow rate, \(\uptau \) is time of fracture leakoff area creation, \({{V}}_{\mathrm{f}}\) is fracture volume, \({{V}}_{\mathrm{l}}\) is fluid loss (no spurt loss), \({{V}}_{\mathrm{sp}}\) is volume loss by spurt, t is time, C is total leakoff coefficient, A is leakoff area (one face of the fracture), \({{S}}_{\mathrm{p}}\) is spurt loss coefficient, \(\alpha _{\mathrm{a}}\) is leak off area parameter and \({{\upalpha }_{\tau }}\) is leak off parameter at the time of fracture
The fluid loss due to leak off during and after pumping fracturing is expressed as Eqs. 5 and 6, respectively:
$$\begin{aligned} \mathrm{{V}}_{\mathrm{l}}(\mathrm {t})= & {} \Pi \hbox {C(t)A(t)}\sqrt{t} \,\, \upvarphi (\alpha _{\mathrm{a}}\alpha _{\mathrm{c}}) \end{aligned}$$
$$\begin{aligned} \mathrm{{V}}_{\mathrm{l}}(\uptheta )= & {} \mathrm {2C(tp)A(tp)} \sqrt{{\textit{tp}}} \, \, \hbox {G} (\alpha _{\mathrm{a}} \alpha _{\mathrm{c2},} \,\, \uptheta ) \end{aligned}$$
where \(\uptheta = \hbox {t/tp}\).
where \(\mathrm{{V}}_{\mathrm{l}}\) is fluid loss (no spurt loss), C is total leakoff coefficient, A is leakoff area (one face of the fracture), t is time, \(\alpha _{\mathrm{a}}\) is leak off area parameter, \(\alpha _{\mathrm{c}}\) is leak off parameter during pumping, \(\alpha _{\mathrm{c2}}\) is reservoir compressibility and viscosity coefficient, \(\mathrm{{t}}_{\mathrm{p}}\) is pumping time, G (\(\uptheta \)) is fluid loss function, \(\uptheta \) is dimensionless time and \(\Pi \) is pie (3.14).
Fig. 2

a (Left) Well design of Cambay Shale used for HF modeling. b (Right) Geomechanics log created in MShale Software. The data points are obtained from the depth-measured log data

Fig. 3

a (Left) Well design of Eagleford Shale b Geomechanical properties of the drilled section. The data points are obtained from the depth-measured log data (Araujo et al. 2012)

Continuity equation (Meyer 2012)

The mass continuity equation in terms of the flow rate per unit length \(q=vW\) is expressed as Eq. 7
$$\begin{aligned} \vec {\nabla } . \vec {q} + 2 \, \mathrm{{q}}_{\mathrm{L}}+ \frac{\partial W}{\partial t} = 0 \end{aligned}$$
where \(\vec {\nabla } . \vec {q}=\frac{\partial qL}{\partial x}+ \frac{\partial _z}{\partial Z}\) and \(\partial _L\) is the leakoff rate per unit leakoff area (i.e., leakoff velocity), q = injection flow rate, W is fracture width, x is lateral coordinate along fracture length and z is vertical coordinate

Momentum conservation (Meyer 2012)

The momentum equation (equation of motion) for steady flow is expressed as Eq. 8
$$\begin{aligned} \vec {\nabla } \, \mathrm {P} = -{\nicefrac {1}{2}}\mathrm {f} \,\, \uprho {\vec {q}}^{2}/ \, \mathrm{{w}}^{3} \end{aligned}$$
$$\begin{aligned} {f} = 24/\mathrm {Re}; \, \mathrm {laminar\, flow} \,and\, f = \mathrm {f R} ({e}, \upvarepsilon ); \, \mathrm {turbulent\, flow} \end{aligned}$$
where f is the Darcy friction factor, Re is the Reynolds number, \(\varepsilon \) is the relative wall roughness, \(\vec {\nabla } \, \mathrm {P}\) is change in pressure, \(\uprho \) is density and q is injection flow rate.

Width opening pressure elasticity condition (Meyer 2012)

The crack-opening and opening pressure relationship can be expressed as Eq. (9)
$$\begin{aligned} W(x,z,t) = \Gamma _w(x,y,z,t) \frac{2 ({1-v})}{G} H_\zeta \Delta P ({x,0,t}) \end{aligned}$$
where \(\Gamma _{\mathrm{w}}\) is a generalized influence function, \(H_\zeta \) is a characteristic half-height, \(\Delta P\) is the net fracture pressure \({P} - \upsigma \), W is fracture width, G is Shear modulus, v is Poisson’s ratio, x is lateral coordinate along fracture length, y is coordinate perpendicular to frac face and z is vertical coordinate

Fracture propagation criteria Stress intensity factor (SIF) controls the fracture propagation and orientation. A propagating fracture can be observed if SIF is equal to the fracture toughness, \(\mathrm {K}_{\mathrm{IC}}\) (Meyer 2012)

Well design: The well design and geomechanical properties of Cambay Shale is presented in Fig. 2a, b. The true vertical depth (TVD) is 920 m. The reservoir properties, i.e., formation pressure is 1500 psi, porosity 15–20%, reservoir temperature is 72 \(^\circ \)C and bottom hole static temperature is 150 \(^\circ \)F. For the Eagleford Shale, the measured depth of the lateral that was drilled was 4040 m, including a lateral of 1400 m (Araujo et al. 2012). Figure 3a, b illustrates the rock mechanical properties and well schematics of the drilled section. Reservoir properties of this shale formation, i.e., permeability is 100–800 nano-Darcy (nD) and net pay thickness of 21 m is used for simulation (Araujo et al. 2012).

4 Hydraulic fracturing job design methodology and data selected

4.1 Fracture treatment design

  • The fracture treatment design and simulation was performed on design mode. A proppant with no foam is selected as treatment type.

  • A linear fluid model is used which assumes a one-dimensional fluid loss.

  • The total leak off coefficient C is the rate of fluid loss to the formation which is set constant here.

  • Wellbore hydraulic model is set empirical for Cambay Shale and user database for Eagleford Shale. This provides a united correlation that is applicable for all fluid types, i.e., Newtonian, highly non-Newtonian and Viscoelastic fluids.

  • The number of fracture solution iterations used is 30. This determines the target number of time steps to be used for the fracture propagation solution.

  • The heat transfer is turned off which predicts the heat up of the fracturing fluid in the wellbore and the exchange of heat transfer in the fracture to the reservoir during fracture propagation.

  • The in situ temperature selected for Cambay and Eagleford Shale is 69 and 100 \(^\circ \)C, respectively.

4.2 Fracture design

  • The fracture geometry selected for both Cambay and Eagleford Shales is three-dimensional. In this planer fracture model, fracture propagation will occur laterally and vertically. This model is selected as it is applicable for all length to height aspect ratios.

  • The capability to allow fluid and proppant to flowback from the fracture is kept off. If flowback is off, crossflow at the time of closure and flowback will not be accepted. Self-similar closure is also kept off.

  • The effect of fluid gradient on fracture pressure is included for design purpose. This means, the pressure distribution within the fracture will include the hydrostatic pressure changes as a function of depth (fracture height) and will affect fracture propagation.

  • Propagation parameters are set at positive growth or default growth.

  • The fracture initiation is set at minimum stress interval for Cambay Shale which uses an initial fracture height equal to 10% of the total perforation interval. For the Eagleford Shale, it is at perforated interval. The other parameters such as fracture friction model, wall roughness and fracture tip effects were kept off.

4.3 Proppant criteria

  • The proppant ramp and flowback is set off. For each fracture stage, a uniform proppant concentration is assumed.

  • Proppant solution is on for Eagleford Shale and off for Cambay Shale. Thus, no proppant transport calculation will be performed for Cambay Shale.

  • Perforation erosion during the treatment is deselected.

  • A conventional link proppant transport methodology has been selected for the design. This option links or couples the proppant transport solution with the fracture propagation solution to simulate the effects of slurry transport on fracture pressure distribution and propagation.

  • A medium settling velocity, i.e., convective transport is selected for proppant transport and settling.

  • Wellbore proppant effects and fracture proppant effects are kept negligible for Cambay Shale. However, for Eagleford Shale, these effects are kept empirical.

4.4 Wellbore hydraulics input data

Cambay Shale
  • The wellbore volume is 20.823 bbl.

  • Injection is simulated through tubing. When the fluid reaches the end of the tubing it will flow through the casing to the perforations.

  • The selected wellbore survey method is minimum curvature.

  • Friction loss multiplier is set at 1. This is used to simulate the additional pressure losses due to collars, joint roughness, and restrictions.

  • The relative pipe roughness option is kept off.

  • The casing and tubing data are given in Table 2.

Table 2

Casing and tubing data for Cambay Shale

Casing data

Tubing data

BHTP reference

MD (m)

OD (in.)

Weight (in.)

ID (in.)

MD (m)

OD (in.)

Weight (in.)

ID (in.)

Ref. name

MD (m)

TVD (m)












Eagleford Shale
  • The wellbore volume is 170.6 bbl.

  • Injection is simulated through casing.

  • The selected wellbore survey method is tangential. The deviation input is inclination. The well is inclined at 90\(\circ \) at 2510 m TVD (Araujo et al. 2012).

  • The value of friction loss multiplier is 1 (assumption).

  • The relative pipe roughness option is kept off. Thus, the friction factor will not be modified in accordance with Prandtl’s universal law expression.

  • The casing and tubing data is given in Table 3.

Table 3

Casing data for Eagleford Shale (Araujo et al. 2012)

Casing Data

MD (m)

OD (in.)

Weight (in.)

ID (in.)





4.5 Proppant type and treatment schedule

4.5.1 Cambay Shale

For the input surface treatment schedule, the selected wellbore fluid type is H530, i.e., Hybor H 25 lb/Mgal WG-11 pH 12. Fluid type is FR01 i.e. Slickwater-1 gal/1000 friction reducer. The closure pressure on proppant is 2350 psi and the type of proppant used is 0001-20/40 Jordan Sand.

4.5.2 Eagleford Shale

For the input surface treatment schedule, the selected wellbore fluid type is HC15, i.e., HCL 15%. Fluid type is FR01, i.e., Slickwater-1 gal/1000 friction reducer. The closure pressure on proppant is 7000 psi and the type of proppant used is 0001-20/40 Jordan Sand. To prevent bridging, minimum number of proppant layers used is 3 and concentration/area for propped fracture is \(0.5\,\mathrm {lbm/ft}^{2}\).

5 Results and discussions

5.1 Cambay Shale hydraulic fracturing model

The pumped input treatment schedule for the hydraulic fracturing designed job have been shown in Fig. 4e. The schedule follows 8-stages out of which two stages are treated with FR01 (slick water) fluid type and other six are treated with H530 (hybor) fluid type. Proppant flushing will start from stage no. 4 and will continue till stage 8. An incremental proppant concentration input have been used for fracture treatment process. The total slurry volume pumped for the treatment is 239.91 bbl with a proppant mass of 15038 lbm. Surface pressure starts increasing as the frac job is initiated (Fig. 4a). This increase will continue until fracture initiation pressure (FIP), i.e., 2600 psi is reached. After FIP, this pressure will drop rapidly to the fracture propagation pressure (FPP) which is at 2200 psi. During this decay period, i.e., from breakdown to shut down pumping period, injection of pad volume, transport of sand to perforation and finally in fracture will occur. There is a small pressure rise after the FPP which reflects the normal fracture extension during the treatment. After 6.5 min, pressure will drop to fracture closure pressure. Pump cycle 2 will start at 10.5 min resulting in fracture reopening.

A symmetric vertical fracture will be created (Fig. 4k) at the end of the fracture job. This frac will be initiated within the low stress regions of the reservoir. Proppant placement in fracture is before shutting down the pump. The fracture geometry is almost symmetric with upper frac height of 22.5 m and lower frac height of 27 m (Fig. 4k). The created frac half-length is 31.3 m, whereas the propped half-length where the proppant have been effectively propped into the created fractures is 30 m (Fig. 4d, k). Opening of fracture increases with time, as the proppant gets placed within the fractured zone. Height and length also increases with time during the proppant placement. The propped width decreases 0.4–0.004 inch as it is moving away from the perforation point which is in between 947 m (MD) and 975 m (MD). It can be seen from Fig. 4k, l that the created width of the fracture is very less. This may be due to the presence of clay minerals.

Proppant concentration and fracture conductivity are more in the lower side of the perforation zone (Fig. 4c, d, g, h). It could be because of low stress layer which is juxtaposed to the perforation zone. The concentration/area of proppant decreases as the length of the fracture approaches to 30 m (Fig. 4b).

The proppant concentration at end of the fracture job and closure has been shown in Fig. 4c, d. Fracture conductivity decreases away from the perforation zone due to less concentration of proppant (Fig. 4g, h).

Refer Table 4 for the details on output generated from MShale simulator. Refer Fig. 6b for three-dimensional fracture model of Cambay Shale.
Fig. 4

Cambay Shale hydraulic fracturing model.a Graph: surface pressure and BHTP vs time. b Graph: concentration/area profile vs length. c Concentration/area (end of job) vs length plot. d Concentration/area closure vs length Plot. e Graph: total slurry volume vs time input treatment schedule g Fracture conductivity—end of job. h Fracture conductivity—closure. f Graph: average pay zone conductivity vs time. g Fracture conductivity—end of job. h Fracture conductivity—closure. i Graph: average width vs length. j Graph: maximum width profile at Perf vs length. k Width contours—end of job and l width contours closure

Table 4

Output generated from MShale simulator

Output parameters

Cambay Shale

Eagleford Shale

Slurry volume injected (bbl)



Liquid volume injected (bbl)



Fluid loss volume (bbl)



Frac fluid efficiency



Net fracture pressure (psi)



Length (one wing)



Upper frac height (m)



Lower frac height (m)



Upper frac height TVD (m)



Lower frac height TVD (m)



Center of perforation (TVD) (m)



Total frac height (m)



Max frac width at perforations (in)



Avg. hydraulic frac width (in)



5.2 Eagleford Shale hydraulic fracture model

The well was designed with two frac stages, each stage having four sets of clusters. Plug and Perf completion method is used for design purpose. The fracturing pumping schedule is as follows

1. First 2 stages Start pumping 1050 bbl of HC15

2. Pad and Prop Stages for other stages Slickwater treatment pad and prop stages with proppant concentration from 0.25 to 1.75 lbm/gal was used.

The total slurry volume pumped for the fracture treatment is 21,500 bbl. All the stages are treated with a 1050-bbl 15% hydrochloric acid (HCL) as it will dissolve the skin due to the formation and can also increase the fracture length. High breakdown and low pumping rates can be achieved by this practice (Araujo et al. 2012). A mesh size of 20/40 Jordan sand is selected for acid-based slickwater fracture treatment. The input treatment schedule for this job is shown in Fig. 5b.

Surface pressure profiles with respect to time is shown in Fig. 5a. which gives the values of fracture initiation pressure, fracture propagation and fracture closure pressure. The perforation point is just above the Buda formation. Buda is a tight carbonate formation with higher stress which act as a frac barrier. Thus, the fractures are propagating into Eagleford shale which is having lower stress as compared to Buda. Height and length increases with time, as proppant gets placed within the fractures zone. The Fracture geometry is almost asymmetric with upper frac height of 47.9 m and lower frac height of 0.37 m. The created total Frac half-length is 155 m, whereas the propped half-length is 115 m where the proppant have been effectively propped into the created fractures (Fig. 5c). Refer Fig. 6a for three-dimensional fracture model of Eagleford shale.

Propped width decreases 1.8–0.2 inch as it is moving away from the perforation point which is at 2510 m. The maximum frac width at perforation is 0.25436 in (Fig. 5c, d). Fracture conductivity decreases away from the perforation zone due to less concentration of proppant.
Fig. 5

Eagleford Shale hydraulic fracturing model. a Graph: surface pressure and BHTP vs time b input treatment schedule. c Width contours. d Width profile @ Perfs vs length plot

Fig. 6

Three Dimensional (3D) model of Eagleford Shale and Cambay Shale

6 Conclusions

Hydraulic fracturing is a technology used to unlock untapped ultra-low permeable shale gas reserves with positive economic returns. It plays an inevitable role in enhancing oil and gas production from unconventional reservoirs. Accurate calculation of fracture height, width, and length are essential for fracture design and production optimization. Geomechanical properties (like Poisson’s ratio, bulk modulus, stress profiles, and toughness, etc.), fracture gradient, and distribution of minimum horizontal stress are important factors in controlling the fracture geometry and design optimization.

The present study is an attempt to model an optimum fracture design in shale sections of Cambay Basin, India and comparing it with a successful case study of US shale play (i.e., Eagleford). As a result, it was observed that low stress zones are geomechanically favourable and suitable for hydraulic fracture initiation and propagation. Cambay Shale shows less frac height and frac half-length as compared to Eagleford Shale. It is probably due to high clay content of Cambay Shale. Clay conditioning may result in better fracture height, width and length and can make this clay-rich shale more producible. On the other hand, in the Eagleford shale, good frac height or fracture geometry was observed above the tight Buda formation.

Realising the importance of shale gas and oil for meeting the energy demands of India and the need to expedite exploration and assessment of domestic unconventional reserves, it is the need of the hour to exploit these untapped shale resources. Presently, there is no commercial production of shale gas/oil in India. An accurate and proper modeling and design of hydraulic fracture of Indian shale can help in predicting the producing capability of this shale. The present study is a mini design of the hydraulic fracturing which can be implemented in real-time operations if augmented with main frac design. This study holds a virtuous place in the India’s vision of exploring and exploiting shale reserves.



We extend our sincere thanks to University of Oklahoma, USA for giving us an opportunity to work in IC3 Laboratory of MPGE. We also thank Reliance Industries Limited, Oil and Natural Gas Cooperation Limited and Pandit Deendayal Petroleum University for their continuous support and cooperation in the successful completion of this paper.

Compliance with ethical standards

Conflict of interest

On behalf of all authors, the corresponding author states that there is no conflict of interest.


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Copyright information

© Springer International Publishing AG, part of Springer Nature 2018

Authors and Affiliations

  1. 1.School of Petroleum TechnologyPandit Deendayal Petroleum UniversityGandhinagarIndia
  2. 2.Oil and Natural Gas Corporation Limited, ONGCAhmedabadIndia

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